This invention relates to a sorbent composition for gas treatment to remove mercury from gas streams, particularly flue gas streams.
Coal-fired power plants contribute over two-thirds of the mercury emissions in the United States. Mercury is found naturally in coals throughout the world. Because it is highly volatile, when coal is burned, nearly all mercury vaporizes and exits the boiler contaminating the flue gas. The mercury in the flue gas may exist in the form of elemental mercury (Hg0), or Hg2+, for example, mercuric chloride (HgCl2) and mercuric oxide (HgO). The proportions of elemental to oxidized forms of mercury depend on the characteristics (components, origin etc.) of the fuel being burned, the combustion method and the flue gas treatment technology. Both elemental and oxidized Hg compounds are a great concern to human health and to the environment. The Clean Air Act Amendment of 1990 designated all forms of mercury as hazardous air pollutants and the U.S. Environmental Protection Agency has set rules to regulate mercury emissions from coal-fired power plants.
The particular form of mercury present in the flue gas plays an important role in the effectiveness of an emission control strategy. The oxidized mercury compounds are by far more easily removed. Existing pollution control devices, such as acid gas scrubbers and particulate control systems, can remove some of the oxidized mercury species. Unfortunately, oxidized mercury typically constitutes only a small fraction of the total mercury content of the flue gas. The removal of elemental mercury is more difficult, requiring the implementation of new control technologies.
To be of practical use in existing power plants, a mercury abatement system should be straightforward to retrofit into existing plant infrastructure, preferably requiring minimal capital investment. One approach that meets this requirement is sorbent injection, particularly dry sorbent injection. In this method, a solid sorbent injected into the flue gas removes the gas phase mercury compounds and then the mercury-laden sorbent is recovered along with the fly ash. The method can be implemented with little or no modification to existing particulate control systems using either a fabric filter (FF) bag house or an electrostatic precipitator (ESP). Preferred sorbents should: (1) be low cost; (2) have high mercury capacity; (3) exhibit good adsorption kinetics; and (4) generate no environmental problems in its own right. Another important consideration is that the sorbent, which is collected with the fly ash, should not limit the normal uses of the fly ash. Much of the fly ash collected in particulate control systems is sold as an extender for Portland cement. Fly ash can replace as much as 80% of the cement in some grades and over 20% of the fly ash generated by U.S. power plants is sold for use in concrete.
A wide range of sorbents have been used for removing mercury from gas streams, including activated carbons, zeolites, transition metals and their oxides/sulfides. The injection of powdered activated carbons (PACs) is a demonstrated control technology for reducing mercury emissions from coal-fired power plants that do not have wet scrubbers. However, activated carbons contaminate the fly ash, particularly when injected in large quantities.
Fly ash that contains carbon is not suitable for cement making. Carbon sorbents recovered with fly ash interfere with the function of air-entraining-admixtures (AEAs) that are added to the cement to generate air pockets (required for workability and freeze tolerance). In one extreme example, in a large-scale test of activated carbon sorbents in a power plant, carbon addition prevented the use of the fly ash in concrete, not only for the duration of the test, but for two weeks after the carbon addition was stopped (Bustard et al., 2002). Even at a modest 3 lb/MMAcf (million actual cubic feet) sorbent injection rate, the carbon content of the fly ash can exceed 1% on a weight basis for almost all types of coals, rendering the fly ash useless as a cement additive. The problem is much more serious than lost sales for the plants. If the fly ash is not salable for concrete, it has no use at all, and becomes an expensive waste problem.
In addition to by-product impacts, the efficacy of the PACs is also greatly reduced in the presence of sulfur oxides in flue gas. Particularly, even small amounts of sulfur trioxide (SO3) cause significant reduction in Hg capacity. Because PACs are non-specific adsorbents, SO3 present in large concentrations adsorbs onto their surfaces, occupying the sites responsible for Hg adsorption.
A number of other approaches have been developed to eliminate Hg emissions as an alternative to PAC injection. One of these is a two-step process; in the first step a heterogeneous catalyst oxidizes Hgo in the flue gas and the oxidized mercury (Hg+2) is removed using a scrubbing solution integrated with the Flue Gas Desulfurization (FGD) absorber (Feely, 2003). The oxidized forms of mercury are much more reactive and readily removed with absorber solutions as well as with adsorbents. However, oxidizing mercury with molecular oxygen is challenging. Mercury is a semi noble metal with reduction/oxidation potential similar to that of palladium. Hence, Hgo cannot be oxidized with standard metal oxide catalysts using gas phase oxygen as oxidizer. A few metal oxides, such as V2O5 can oxidize elemental mercury using lattice oxygen through a Mars and Van Krevelen-type mechanism; however, the rates are very slow (Granite et al., 2000).
Noble metal catalysts and a few metal oxides can catalyze mercury oxidation using strong oxidizers that are already present in the flue gas, such as chlorine (Cl2), hydrochloric acid (HCl) and nitrogen dioxide (NO2) (Miller et al., 2000). However, these oxidizing agents are only present at relatively low concentrations and consequently, the rate of mercury oxidation is very slow. Further, the concentrations of HCl and NO2 vary widely depending on the fuel type and boiler design, making it difficult to develop a universal Hg control solution for all power plants. For example, a process that works for high chlorine lignite coals may not be applicable to low chlorine bituminous coals. In addition, all catalytic mercury oxidation systems rely on FGD wet scrubbers to remove the oxidized mercury species, which may not be available for a given power plant.
The addition of strong oxidizers (such as Cl2, Br2, CaBr2) to the flue gas (or sometimes to the boiler as part of the coal feed) has been explored. U.S. Pat. No. 6,878,358, for example, relates to mercury removal from flue gas by feeding bromine compounds, such as an aqueous HBr solution or NaBr, into a furnace or into flue gas to oxidize the mercury. Although these approaches have been proven effective, it was also found that the use of these highly corrosive additives can damage process equipment. The slippage of the halogens (e.g. Cl2, Br2) is also problematic, contributing to the emission of additional pollutants from the power plants.
US2003157008 discloses the use of pure manganese oxides for the removal of mercury compounds. However, these materials also show relatively modest mercury capacities, which make their use uneconomical in power plants. US2010005963 claims a sorbent compromising a co-precipitated manganese oxide zirconium oxide combination at 1:1 molar ratio
There is a significant need in the art for efficient and cost effective methods for removal of mercury from gases which do not detrimentally affect commercial use of fly ash.